Hydrocarbon Processing - August 2021 - GP-26

ENGINEERING AND DESIGN
to operate with a pressure of 31 psig at the top and 34 psig
at the bottom, corresponding to temperatures of 226°F at the
top and 275°F at the bottom. These conditions were sufficient
to achieve a specification of less than 10 ppmw H2
S in the bottom
product.
In the stripping section of the SWS column, the sour water
is contacted counter-currently with the steam to free the H2
and CO2
S
. This sour water feed flows downward in the column,
and steam is injected into the column to strip out the acid gases
from the sour water. The steam injection rate to the SWS is
controlled by monitoring the column overhead temperature.
As the temperature increases, the steam flow decreases. Acid
gases from the stripper column are combined with acid gases
leaving from the sour water pre-flash drum to the acid flare
header and recovered in the FGRS. Water, leaving the column
from the bottom side, flows to the evaporation pond with H2
< 10 ppmw, as per company standard.2
S
Sour water from slug catchers
and three-phase separators
Pre-flash drum
Sour water feed filter
Acid gas
to SRU
Initial unit operation. A standalone SWS unit was installed
at a gas plant to treat the produced water at the facility, but
it was not performing as required. As per actual unit operation,
the column feed flowrate was running at very low rates
compared to the design rate of 5,000 bpd. At approximately
40%-50% of the design feedrate, the treated water started to
go off specification, and the column pressure started to fluctuate.
The top temperature fell dramatically, and the column
pressures fell from their setpoints of 31 psig/34 psig. The only
way of bringing the tower back under control was to reduce
the column feedrate. The column was gradually brought back
up to design temperature and pressure.
Several attempts were made (with small variations) to increase
the feed to the design flowrate. Each attempt resulted
in the same scenario, as previously described. The operating
behavior and distributed control system (DCS) data were
closely reviewed to establish the root cause of the problem. At
feed flowrates below 1,000 bpd, the column ran without issue,
with all parameters in the correct operating range. As the column
feedrate increased above 1,000 bpd, an upset occurred in
column pressure drop across the packing. Initially, the operators
observed a rapid increase in pressure drop followed by an
equally rapid fall. These peaks became more dramatic as the
column feed increased, until the product went off specification.
The sudden changes in column pressure drop are a primary
Sour water
stripper
column
Sour feedwater
pump
LP steam
Treated
Treated water
to
evaporation
pond
FIG. 2. Simplified PFD for the SWS.
Flash gases
3
Sour water feed
Pre-flash
drum
2
PUMP-100
Q-1
Stripping steam
Stripping water
6
Q-3
5
FAXR-100
Q-2
FIG. 3. Simulation model for the SWS.
26 JULY/AUGUST 2021 | GasProcessingNews.com
To evaporation pond
PUMP-100
1
2
SWS column
Overheads
water pump
Treated water cooler
symptom of flood. Pressure fluctuations and a drop in the overhead
temperature are also symptoms of flood. Fluctuations
in the column sump level, which followed the pressure drop
fluctuations, were also noticed and provided an additional
symptom of flood. It was concluded that above a certain feed
flowrate, the column became flooded. At this stage, the cause
of the operational upset was unknown since the column was
designed to operate under a much higher feed flowrate.
Study objective. The objective of the study was to assess and
restore the performance of the existing SWS at the gas plant
to process the sour water according to its design capacity. This
study highlights the main findings and recommendations to resolve
the major challenges of the SWS unit operation.
Sour water stripping is a process in
which either external steam or steam
generated by a reboiler-or even a hot
hydrocarbon stripping vapor-is used to
shift chemical reaction equilibria by heating
the sour water.3
The steam is the " gaseous
solvent " used to remove and carry
H2
S out of the system. In other words,
the application of heat generates internal
stripping steam (equivalently, live steam
injection can be used) and carries ammonia,
H2
S and CO2
out of the water by:
* Heating the sour water feed to
boiling point
* Reversing chemical reactions
* Diluting the partial pressure of
the gases stripped by furnishing
excess steam.
The process is similar to an amine
regenerator; however, SWS does not
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Hydrocarbon Processing - August 2021

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